Choke system

ABSTRACT

A method and apparatus for controlling pressure in a drilling system that includes a drilling fluid return flow path. Steps include providing a choke system comprising a first flowline having an inlet and an outlet each connected to the drilling fluid return flow path, wherein the outlet connects to the return flow path downstream of the inlet connection, a first choke positioned on the flowline, a second choke positioned on the flowline downstream of the first choke, and a control module for controlling the first and second chokes; flowing drilling fluid through the first flowline while at least one of the first and second choke is partially closed so as to cause a pressure drop; in response to an input, opening the partially closed choke and partially closing the other choke so as to substantially maintain the pressure drop; returning the chokes to the original flow status.

TECHNICAL FIELD/FIELD OF THE DISCLOSURE

The present disclosure relates to an integrated, self-cleaning choke for use in oil field operations including managed pressure drilling or other applications where cleaning of valves may be an issue.

BACKGROUND OF THE DISCLOSURE

Drilling systems often include mud handling systems comprising various combinations of pumps, flowlines, shakers, and pits. Offshore drilling systems may include a riser through which drilling fluid returning to the surface can be brought to the mud handling system.

When drilling a wellbore, fluids in the underground formation surrounding the wellbore are under pressure. In order to prevent wellbore fluids flow into the wellbore, drilling fluid, commonly known as drilling mud, is introduced into the wellbore. If sufficient, the hydrostatic pressure of the drilling mud against the wellbore can prevent the fluid from entering the wellbore. When the hydrostatic pressure of the drilling mud equals the formation pressure, the drilling operation is typically referred to as balanced. Typically, a wellbore is drilled slightly overbalanced, i.e. the hydrostatic pressure of the drilling mud is higher than the formation pressure.

The International Association of Drilling Contractors (IADC) Subcommittee on Underbalanced Pressure Drilling defines Managed Pressure Drilling (MPD) as “an adaptive drilling process used to more precisely control the annular pressure profile throughout the well-bore. The objectives are to ascertain the downhole pressure environment limits and to manage the annular hydraulic pressure profile accordingly. This may include the control of back pressure by using a closed and pressurized mud returns system, downhole annular pump or other such mechanical devices. Managed Pressure Drilling generally will avoid flow into the well bore.”

In some instances, however, underbalanced drilling, in which the hydrostatic pressure of the drilling fluid falls below the formation pressure, may occur and fluid from the formation may flow into the well. This increase in fluid flow is known as a kick. If a kick is not contained, a blowout may occur. Kicks may be caused by insufficient mud weight, improper hole fill-up during trips, swabbing, gas cut mud, or lost circulation. In order to reduce the risk of blowouts, drilling rigs utilize various pressure control devices, including blow out preventers, choke manifolds, Kelly-Cocks, and flapper discs. Thus, MPD generally aims to maintain the bottom hole pressure slightly above the pore pressure of the formation without exceeding a fracture pressure of the formation.

As a production field ages, subsurface reserves may become inaccessible by conventional methods, if, for example, the pressure margins are reduced by reservoir depletion. In addition, Non Productive Time (NPT) can make a project uneconomical. Reduction of NPT and improved drilling practices can have significant financial impacts on a project. NPT associated with kicks and lost circulation has both an immediate impact and NPT may also lead to additional mud cost, additional casing strings, stuck pipe and unplanned side tracking. MPD is one technique for addressing these problems, as it can make it possible to access conventionally inaccessible reserves and to reduce NPT.

There are various ways to achieve MPD, including manual MPD, which relies on a choke operator, and automatic MPD. There are also back pressure MPD and dual-gradient (DG) methods. DG systems have a subsea pump for the return flow and the upper part of the riser partly filled with mud and partly with a lighter fluid, which may be water or gas.

In MPD, the annulus may be closed using a pressure containment device. This device includes sealing elements that engage the outside surface of the drill string so that fluid flow between the sealing elements and the drill string is substantially restricted. The sealing elements may allow for rotation of the drill string in the borehole so that the drill bit on the lower end of the drill string may be rotated. A flow control device may be used to provide a flow path for the removal of drilling fluid from the annulus. After the flow control device, a pressure control manifold, with at least one adjustable choke, valve and/or the like, may be used to control the rate of flow of drilling fluid out of the annulus. When closed during drilling, the pressure containment device creates backpressure in the borehole. The backpressure can be controlled by using the adjustable choke or valve on the pressure control manifold to control the flow of drilling fluid out of the annulus/riser annulus.

During MPD, an operator may monitor and compare the flow rate of drilling fluid into the drill string with the flow rate of drilling fluid out of the annulus to detect whether there has been a kick (fluid inflow), or whether drilling fluid is being lost to the formation. A sudden increase in the volume or volume flow rate out of the annulus relative to the volume or volume flow rate into the drill string may indicate that there has been a kick. By contrast, a sudden drop in the flow rate out of the annulus relative to the flow rate into the drill string may indicate that the drilling fluid has penetrated the formation and is being lost to the formation during the drilling process.

SUMMARY

The present disclosure provides for a choke system for controlling pressure in a hydrocarbon production, geothermal, or other drilling system that includes a drilling fluid return flow path, the choke system comprising a first flowline having an inlet and an outlet that are each connected to the drilling fluid return flow path, wherein the outlet connects to the drilling fluid return flow path at a point that is downstream in the drilling fluid return flow path of the inlet connection, a first choke positioned on the flowline, a second choke positioned on the flowline downstream of the first choke, and a system for controlling the first and second chokes.

The choke system may further include a second flowline connected to the drilling fluid return flow path in parallel with the first flowline and the second flowline may include at least two additional chokes arranged in series. The first flowline may include at least three chokes arranged in series. The choke system may further include a rotating control device (RCD) or pressure control device (PCD), or other similar devices that seal around a drill string, comprising at least one rotating sealing element and a housing defining a flow path that forms part of the drilling fluid return flow path, wherein the first flowline inlet is in fluid communication with the flow path at a point upstream of the sealing element and the first flowline outlet is in fluid communication with the flow path at a point downstream of the sealing element.

In some embodiments, the choke system of claim 1 may be incorporated as part of a drilling riser. In some embodiments, a drilling system for a rig having mud handling system, may comprise a riser, an RCD installed in the riser, and a choke system in fluid communication with the RCD so that fluid flow through the riser can bypass the RCD via the choke system and the fluid flow from the choke system can be routed back into the riser and will enter the mud handling system, which may include flowlines, shakers, and pits.

In some embodiments, a method for controlling pressure in a drilling system that includes a drilling fluid return flow path, the method comprises a) providing a choke system comprising: a first flowline having an inlet and an outlet each connected to the drilling fluid return flow path, wherein the outlet connects to the drilling fluid return flow path at a point that is downstream in the drilling fluid return flow path of the inlet connection, a first choke positioned on the flowline, a second choke positioned on the flowline downstream of the first choke, and a system for controlling the first and second chokes; b) flowing drilling fluid through the first flowline while at least one of the first and second choke is partially closed so as to cause a predetermined pressure drop between the inlet and the outlet; c) in response to a predetermined input, flowing drilling fluid through the first flowline while fully opening the partially closed choke of step b) and partially closing the other choke so as to substantially maintain the predetermined pressure drop; d) flowing drilling fluid through the first flowline while returning the first and second chokes to the flow status of step b); and e) repeating steps b)-d). The drilling system may be a hydrocarbon production drilling system, geothermal drilling system, or other drilling system in which drilling fluid is pumped into a well and returned to the surface under controlled pressure.

The predetermined input may be a time input, a pressure change in the drilling fluid return flow path, or a pressure change in the first flowline. The choke system may further include a second flowline connected to the drilling fluid return flow path in parallel with the first flowline and including at least two additional chokes arranged in series, and the method may further include flowing drilling fluid through the second flowline and opening and closing the additional chokes while maintaining the predetermined pressure drop. At least one flowline may include at least three chokes arranged in series and at least one of the at least three chokes may be partially closed at each step.

Step a) may include providing a rotating control device (RCD) that comprises at least one rotating sealing element and a housing defining an RCD flow path that forms part of the drilling fluid return flow path, wherein the first flowline inlet is in fluid communication with the RCD flow path at a point upstream of the sealing element and the first flowline outlet is in fluid communication with the RCD flow path at a point downstream of the sealing element, and step b) may include flowing drilling fluid through the RCD flow path. The method may further comprise controlling the chokes in steps b)-d) such that the pressure drop between the inlet and the outlet varies from the predetermined pressure drop by less than 10 bar.

The present system can be advantageously incorporated into an existing system without requiring modifications to the rig or mud handling system, while still supporting MPD operations.

BRIEF DESCRIPTION OF THE DRAWINGS

The present disclosure is best understood from the following detailed description when read with the accompanying figures. It is emphasized that, in accordance with the standard practice in the industry, various features are not drawn to scale. In fact, the dimensions of the various features may be arbitrarily increased or reduced for clarity of discussion.

FIG. 1 is a schematic partial cross-section of a choke system in accordance with one embodiment of the invention.

FIG. 2 is a schematic illustration of a method of operating self-cleaning chokes in accordance with the present invention.

DETAILED DESCRIPTION

It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments. Specific examples of components and arrangements are described below to simplify the present disclosure. These are, of course, merely examples and are not intended to be limiting. In addition, the present disclosure may repeat reference numerals and/or letters in the various examples. This repetition is for the purpose of simplicity and clarity and does not in itself dictate a relationship between the various embodiments and/or configurations discussed.

FIG. 1 is a schematic partial cross-section of a choke system 100 in accordance with an embodiment of the invention connected to a rotating control device (RCD) 200. Choke system 100 may be used in a drilling system and more particularly in a drilling operation in which it is desirable to apply back pressure on the returning drilling fluid. Thus, in an exemplary embodiment, choke system 100 may be connected to RCD 200, which may in turn be connected to a blowout preventer (BOP) stack (partially shown at 10), which in turn may be coupled to a well casing that extends into a wellbore. A drill string 25 may extend through RCD 200 and the BOP stack and into the casing. In some embodiments, RCD 200 includes a housing 101 and a flowline 112 may connect choke system 100 to RCD 200 via an inlet channel 212 and an outlet channel 214 through the wall of housing 101. In some embodiments, to reduce the risk of blockage, the ID of flowline 112 may be greater than the ID of inlet channel 212 and less than the ID of outlet channel 214.

In some instances, such as sub-sea operations, the system may be installed as a part of a sub-sea riser. The system may be designed as a riser joint with locking system for the RCD and an integrated choke system. In a configuration like this, the system can be installed at any pre-determined depth to optimize the pressure curves for the well. In embodiments in which the system is installed as a part of a sub-sea riser, the rig's original mud handling system may be used as originally intended and MPD operations can be controlled and operated outside of the rig, leaving the rig unmodified, thereby reducing the deck space needed for MPD equipment.

In some embodiments, the flow may be routed via hoses and/or piping directly to the mud system. For example, in riserless drilling where the riser or a part of the riser above the RCD is removed, drilling fluid may be routed by other means back to the drilling facility or to other means of mud handling systems.

As described in commonly owned U.S. Application No. 16/113,315, in some embodiments, RCD 200 may include a housing 101 containing a seal assembly package (SAP) 213 and a seal tube assembly 210. Housing 101 may include a lower flange 203 adapted to couple to another component, such as a BOP stack 10. Housing 101 defines an RCD flow path 103 that forms a continuous bore with the adjacent equipment. Housing 202 may also include an upper flange 205, which may be used to couple RCD 200 to another component, such as a riser section as discussed further herein below. For example and without limitation, upper flange 205 may be used to couple RCD 200 to one or more of a pump, washing device, or wiper. In some embodiments, upper flange 205 may not be connected to any additional component. In some embodiments, housing 101 may further include one or more additional ports through which fluid may flow into or out of housing 101. In some embodiments, one or more ports may fluidly couple to flanges 109, to which other equipment may be coupled, such as, for example and without limitation, choke manifolds, pressure gauges, static flow check equipment, valves, etc.

As further described in commonly owned U.S. application Ser. No. 16/113,315, seal tube assembly 210 may include a seal tube 263 and bearing assemblies 265. SAP 213 may include an SAP outer body 233, an SAP inner body 231, a mandrel 227, and a sleeve 234 that abuts and seals an outer surface of SAP 213 to the inner surface of housing 101. In some embodiments, SAP 213 may further include a locking ring 215 that mechanically couples to seal tube assembly 210 and locks SAP 213 to housing 101.

Although described above as being positioned atop BOP stack 10, it will be understood that RCD 200 may be included as part of a riser assembly according to any desired configuration. For example, a lower riser section may couple to lower flange 203 of housing 202, and an upper riser section may couple to upper flange 205 of housing 202. Alternatively, to simplify installation and increase the flexibility of the system, the choke system 100 may be connected to a housing that is included as an integrated part of the riser. All connections can be made with flanges, snap-couplings or other suitable connection types.

As mentioned above, inlet channel 212 allows fluid communication between choke system 100 and RCD 200. In some embodiments, inlet channel 212 may be in fluid communication with RCD flow path 103 at a point upstream of the sealing element and outlet channel 214 may be in fluid communication with the RCD flow path 103 at a point downstream of the sealing element. As used herein, “upstream” refers to the normal direction of fluid flow through the component in question. Thus, for example, because fluid will normally flow upward (as drawn) through RCD flow path 103, upstream components will be below downstream components (as drawn).

In some embodiments, choke system 100 includes flowline 112 and a flow control module 110, at least two valves, or chokes, 130, 150, and a control module 160. In some embodiments, an optional sensor 170 may be included. Sensor 170 may be a gas sensor that senses released gas after the pressure drop from the choke system or may be a second sensor or controller to measure other parameters related to the flow through choke system 100. Flow control module 110, and chokes 130, 150, optional additional valves, and optional sensor 170 may all be arranged in series on flowline 112. Control module 160 may be adapted to control chokes 130, 150 and may also be connected to additional devices via an umbilical (not shown). Control module 160 may also be adapted to control flow control module 110. Flow control module 110 may be configured to measure the amount of liquid, gas, and solids passing through the flowline and may use the measured data as the basis for controlling the valves and regulate the pressure in the well (MPD). Examples of parameters that may be measured include mud-weight, viscosity, temperature, rheology.

Chokes 130, 150 provide the present the choke-/pressure control system. Two or more valves can be provided to ensure functionality and contingency of the system. While the present system is not limited to a particular type of valve, in some embodiments, the maximum ID of each choke 130, 150 will be the same or larger than the ID of flowline 112 so as to ensure that no blockage of the chokes 130, 150 can occur when the valves are 100% open.

In some embodiments, the actuating system (not shown) for controlling each choke 130, 150 is integrated in the respective choke 130, 150. The valve actuators may be operated by any suitable means, e.g. electrical, hydraulic, or pneumatic means, according to commercial availability, system requirements, operator requirements, location of the equipment (top-side or sub-sea), local legislation, and the like.

In some embodiments, second and further choke systems 180 may be included on RCD 200 in parallel with choke system 100, as shown in phantom in FIG. 1, or on a second RCD. Alternately or in addition, if desired, flowline 112 may be manifolded so that additional valves (not shown) sharing the same inlet 212 and outlet 214 can be provided in parallel with chokes 130, 150. If present, additional chokes systems 180 and/or additional valves may be controlled by control module 160 or by a second control module in communication with control module 160.

In operations, control module 160 receives signals from the operator's control panel (not shown) and data from the system, such as seal status, well pressure, valve positions and the like. Control module 160 processes the received signals and data and transmits instructions to the different parts of the system. On top-side systems, control module 160 can be simplified due to the ability to get access on a top-side installation.

Because the present choke system 100 provides two or more valves in series, the valves can be actuated in a manner that enables clearing of blockages without taking the system offline. Choke system 100 cycles the chokes 130, 150 so that a predetermined pressure or pressure range is maintained on the pressure- or well-side of the chokes. Specifically, when the first choke 130 begins to be clogged the system will sense increased back pressure in the annulus. In response, control module 160 may begin to open first choke 130 while simultaneously partially closing second choke 150 in order to maintain a stable pressure drop across choke system 100. Opening first choke 130 allows the debris or blockage to flow past first choke 130.

When the first choke 130 is clear, first choke 130 closes and second choke 150 opens to let the debris pass through the system. If choke system 100 includes more than two valves, each successive valve closes as the valve upstream of it opens and then opens as the valve upstream of it closes. In this manner, debris can be passed completely through choke system 100 without requiring a cessation of flow and without causing fluid pressure to rise above desired levels. In some instances, more than one clearing cycle may be needed in order to allow all of the accumulated debris to pass through the choke system. To ensure a proper cleaning of the valve, it is recommended that each choke valve open fully before fully or partially re-closing.

The chokes 130, 150 may be actuated in different ways. In some embodiments, chokes 130, 150 may be operated manually by an operator based on pressure readings. For example, if there is a pressure increase caused by clogging/debris, an operator may initiate a clearing cycle. In this way, the valves may be operated as described to “flush” out the debris by fully open the valve, while the other valve will close to compensate the pressure drop caused by the valve that is being opened. Similarly, the system may automatically respond to changes in pressure and may clear the choke valves according to pre-set parameter values. Alternatively or in addition, choke system 100 may be operated according to a time cycle. In these embodiments, one choke 130 will cycle from the set value (pressure) to fully open, while the other valve closes to compensate for the pressure loss of the first valve so as to maintain a stable well pressure. This cycling may be performed continuously or at predetermined intervals, e.g. one cycle every two minutes.

Regardless of the mode of actuation, an objective of choke system 100 is to maintain the pressure in the well stable during operation so as to avoid any damage such as might be caused by an unexpected influx or loss of fluids in the well. The choke valves operate simultaneously and in cooperation to keep the pressure stable during operations.

In some embodiments, the last valve in the flow direction may be used as the main valve that regulates well backpressure. If there is any increase in the pressure in front of the valve that is not caused by other drilling parameters such as a reduced pump rate or reduction in the flow rate, the pressure increase may be an indication of that the valve is clogged. To clear the valve, the main valve can be opened to 100%, allowing the restriction to be passed through the valve. In order to keep a steady pressure in the system, one or more valve(s) upstream of the main valve will have to close to compensate for the opening of the main valve, to ensure the overall pressure is kept stable.

Referring to FIG. 2, in an exemplary embodiment, choke 130 may initially be 50% closed so as to maintain a predetermined well pressure of 30 bar, as shown at A). The second valve in the series, choke 150 will be fully open, letting all solids that pass through choke 130 also pass through choke 150. Based either on time, flow rate and/or pressure, choke 130 will begin to open and choke 150 will begin to close, as shown at B). This operation will continue until choke 130 is 100% open and choke 150 is 50% open, as shown at C), thereby maintaining a substantially constant pressure against the well. Because choke 130 has an ID that is the same as or larger than the ID of flowline 112, opening choke 130 fully allows solids that may be blocking/obstructing the flow in front of choke 130 to flow through choke 130 and move to the next valve in flowline 112. Choke 130 will then begin to close and choke 150 will begin to close, as shown at D). This continues until choke 130 is 50% again open and choke 150 is 100% open, as shown at A). In some embodiments, the closing of an open choke and the associated opening of other chokes may occur after a pre-set amount of time and/or in response to a signal from an operator. The cycling may continue, alternately opening and closing choke 130 and choke 150, so as to let solids pass through flowline 112 and clear the chokes of obstructions. In some embodiments, in addition to clearing in response to an indication of blockage, clearing cycles can be performed substantially continuously, as an automatic, time-based function or when desired, and may be controlled by an operator and/or automatically. If desired, either choke 130 or 150 may serve as a “primary” or “main” choke valve, i.e. the valve that sets the back pressure when the system is in a default configuration.

In some embodiments, a control module 160 uses inputs from flow and pressure sensors to ensure a stable well pressure and flow as chokes 130, 150 are cycled. In some embodiments, control module 160 may be programmed to maintain the back pressure at choke system 100 within a specified range of a target pressure. In some embodiments, the specified range may be ±50 bar, ±10 bar, or ±5 bar. In many embodiments, in order to enable optimal control of drilling operations, unintended fluctuations in the well pressure are minimized. Sudden clogs may cause pressure fluctuations, but system 100 may be configured to respond quickly actuate chokes 130, 150 so as to keep unintended pressure changes to a minimum. By way of example, when one choke becomes clogged, control system 160 and chokes 130, 150 may be configured to complete a cleaning cycle, i.e. close the open check and open the clogged choke and repeat until the clog has passed through system 100, in less than 60 seconds, in less than 30 seconds, or in less than 10 seconds. In some embodiments, control system 160 may be configured to initiate a second cleaning cycle less than 10 seconds or less than 5 seconds after the first cleaning cycle, if control system 160 detects that a choke is still clogged or has become clogged again. In some embodiments, system 100 is configured such that chokes 130, 150 respond immediately to changes in the well pressure. In some embodiments, the cycle time can be preset or the opening/closing cycle can be triggered by both time and sensor inputs. It will be understood that the drawings illustrate one simplified embodiment and that actual systems will be more complex. For example, to ensure a stable well pressure, multiple flow and pressure sensors may be positioned at different locations relative to choke system 100 and the choke positions may be controlled and regulated by a computer.

Referring again to FIG. 1, in some embodiments and as mentioned above, two or more choke systems 100 can be provided in parallel so that one (or more) may function as a contingency. By way of example, a second choke system 180 (show in phantom) may be connected to RCD 200 on the opposite side from choke system 100. In some embodiments, control system 160 also controls second choke system 180. Each choke system may be separately connected to RCD 200, to other components of the drilling system, or, in marine systems, to other locations on the riser.

Choke system(s) 100 can be adapted to different needs or complexity of each well. For example, in a simple well where a certain pressure variation may be accepted, a system with only one choke system may be sufficient. If problems occur, the operation may be paused and the fault can be sorted before startup. In more complex wells and in subsea configurations, the cost of down time and risk of damage to the well may justify the use of two (or more) systems to reduce the risk of system failure. In addition, one or each choke system may include a pressure relief valve to relieve fluid pressure in case of sudden plugging so as to avoid fracturing the well.

According to some embodiments, the present choke system can be used in conjunction with an offshore rig's mud handling system without requiring that the drilling fluid be taken out of the riser and transferred via hoses or similar, to a rig choke mounted on the rig. Choke system 100 allows simpler installation and use and can be installed on any existing rig. A rig's existing mud handling system can be used without any modification apart from a connection to the rig's riser. Choke system 100 can be installed on any riser depth and can be used to optimize pressure curves related to the pressures in the formation below. Choke system 100 can be an integrated part of the drilling riser. If no RCD is installed, choke system 100 may be installed at any location of the regular riser, and will function in place of a regular riser.

The foregoing outlines features of several embodiments so that a person of ordinary skill in the art may better understand the aspects of the present disclosure. Such features may be replaced by any one of numerous equivalent alternatives, only some of which are disclosed herein. One of ordinary skill in the art should appreciate that they may readily use the present disclosure as a basis for designing or modifying other processes and structures for carrying out the same purposes and/or achieving the same advantages of the embodiments introduced herein. One of ordinary skill in the art should also realize that such equivalent constructions do not depart from the spirit and scope of the present disclosure and that they may make various changes, substitutions, and alterations herein without departing from the spirit and scope of the present disclosure. 

What is claimed is:
 1. A choke system for controlling pressure in drilling system that includes a drilling fluid return flow path, the choke system comprising: a first flowline having an inlet and an outlet that are each connected to the drilling fluid return flow path, wherein the outlet connects to the drilling fluid return flow path at a point that is downstream in the drilling fluid return flow path of the inlet connection; a first choke positioned on the flowline; a second choke positioned on the flowline downstream of the first choke; and a system for controlling the first and second chokes.
 2. The choke system of claim 1, further including a second flowline connected to the drilling fluid return flow path in parallel with the first flowline, the second flowline including at least two additional chokes arranged in series.
 3. The choke system of claim 1 wherein the first flowline includes at least three chokes arranged in series.
 4. The choke system of claim 1, further including a rotating control device (RCD) or pressure control device (PCD) comprising at least one rotating sealing element and a housing defining a flow path that forms part of the drilling fluid return flow path, wherein the first flowline inlet is in fluid communication with the flow path at a point upstream of the rotating sealing element and the first flowline outlet is in fluid communication with the flow path at a point downstream of the rotating sealing element.
 5. The choke system of claim 4, further including a second flowline connected to the RCD flow path in parallel with the first flowline, the second flow line including at least two additional chokes arranged in series.
 6. A drilling riser including the choke system of claim 1 incorporated as part of the riser.
 7. The choke system of claim 1, wherein the choke system is incorporated into a hydrocarbon production drilling system or geothermal drilling system.
 8. A drilling system for a rig having mud handling system, comprising: a riser; a rotating control device (RCD) installed in the riser; and a choke system according to claim 1 in fluid communication with the RCD so that fluid flow through the riser can bypass the RCD via the choke system; wherein the fluid flow from the choke system is adapted to be routed back into the riser and the mud handling system.
 9. A method for controlling pressure in a drilling production system that includes a drilling fluid return flow path, the method comprising: a) providing a choke system comprising: a first flowline having an inlet and an outlet each connected to the drilling fluid return flow path, wherein the outlet connects to the drilling fluid return flow path at a point that is downstream in the drilling fluid return flow path of the inlet connection; a first choke positioned on the flowline; a second choke positioned on the flowline downstream of the first choke; and a control module for controlling the first and second chokes; b) flowing drilling fluid through the first flowline while at least one of the first and second choke is partially closed so as to cause a predetermined pressure drop between the inlet and the outlet; c) in response to a predetermined input, flowing drilling fluid through the first flowline while fully opening the partially closed choke of step b) and partially closing the other choke so as to substantially maintain the predetermined pressure drop; d) flowing drilling fluid through the first flowline while returning the first and second chokes to the flow status of step b); and e) repeating steps b)-d).
 10. The method of claim 9 wherein the predetermined input is a time input.
 11. The method of claim 9 wherein the predetermined input is a pressure change in the drilling fluid return flow path.
 12. The method of claim 9 wherein the predetermined input is a pressure change in the first flowline.
 13. The method of claim 9 wherein the choke system further includes a second flowline connected to the drilling fluid return flow path in parallel with the first flowline, the second flowline including at least two additional chokes arranged in series, and further including flowing drilling fluid through the second flowline and opening and closing the additional chokes while maintaining the predetermined pressure drop.
 14. The method of claim 13 wherein at least one flowline includes at least three chokes arranged in series and wherein at least one of the at least three chokes is partially closed at each step.
 15. The method of claim 9 wherein step a) includes providing a rotating control device (RCD) comprising at least one rotating sealing element and a housing defining an RCD flow path that forms part of the drilling fluid return flow path, wherein the first flowline inlet is in fluid communication with the RCD flow path at a point upstream of the sealing element and the first flowline outlet is in fluid communication with the RCD flow path at a point downstream of the sealing element, and wherein step b) includes flowing drilling fluid through the RCD flow path.
 16. The method of claim 15, further including a second flowline connected to the RCD flow path in parallel with the first flowline, the second flowline including at least two additional chokes arranged in series.
 17. The method of claim 15, further comprising controlling the chokes in steps b)-d) such that the pressure drop between the inlet and the outlet varies from the predetermined pressure drop by less than 10 bar. 